Single Trip Multi-Zone Completion Systems and Methods

ABSTRACT

Disclosed are systems and methods of producing from multiple production zones with a single trip multi-zone completion system. One single trip multi-zone completion system includes an outer completion string having at least one sand screen arranged thereabout and an interval control valve coupled to the at least one sand screen, a production tubing communicably coupled to the outer completion string at a crossover coupling, a control line extending external to the production tubing and being communicably coupled to the crossover coupling, and a surveillance line extending from the crossover coupling external to the outer completion string and interposing the at least one formation zone and the at least one sand screen, the surveillance line being communicably coupled to the interval control valve.

BACKGROUND

The present invention relates to the treatment of subterraneanproduction intervals and, more particularly, to gravel packing,fracturing, and production of multiple production intervals with asingle trip multi-zone completion system.

In the production of oil and gas, recently drilled deep wells reach asmuch as 31,000 feet or more below the ground or subsea surface. Offshorewells may be drilled in water exhibiting depths of as much as 10,000feet or more. The total depth from an offshore drilling vessel to thebottom of a drilled wellbore can be in excess of six miles. Suchextraordinary distances in modern well construction cause significantchallenges in equipment, drilling, and servicing operations.

For example, tubular strings are introduced into a well in a variety ofdifferent ways. It may take many days for a wellbore service string tomake a “trip” into a wellbore, which may be due in part to the timeconsuming practice of making and breaking pipe joints to reach thedesired depth. Moreover, the time required to assemble and deploy anyservice tool assembly downhole for such a long distance is very timeconsuming and costly. Since the cost per hour to operate a drilling orproduction rig is very expensive, saving time and steps can be hugelybeneficial in terms of cost-savings in well service operations. Eachtrip into the wellbore adds expense and increases the possibility thattools may become lost in the wellbore, thereby requiring still furtheroperations for their retrieval. Moreover, each additional trip into thewellbore oftentimes has the effect of reducing the inner diameter of thewellbore, which restricts the size of tools that are able to beintroduced into the wellbore past such points.

To enable the fracturing and/or gravel packing of multiplehydrocarbon-producing zones in reduced timelines, some oil serviceproviders have developed “single trip” multi-zone systems. The singletrip multi-zone completion technology enables operators to perforate alarge wellbore interval at one time, then make a clean-out trip and runall of the screens and packers at one time, thereby minimizing thenumber of trips into the wellbore and rig days required to completeconventional fracture and gravel packing operations in multiple payzones. It is estimated that such technology can save in the realm of $20million per well in deepwater completions. Since rig costs are so highin the deepwater environment, more efficient and economical means ofcarrying out single trip multi-zone completion operations is an ongoingeffort.

SUMMARY OF THE INVENTION

The present invention relates to the treatment of subterraneanproduction intervals and, more particularly, to gravel packing,fracturing, and production of multiple production intervals with asingle trip multi-zone completion system.

In some embodiments, a single trip multi-zone completion system isdisclosed. The system may include an outer completion string having atleast one sand screen arranged thereabout and an interval control valvecoupled to the at least one sand screen, a production tubingcommunicably coupled to the outer completion string at a crossovercoupling, a control line extending external to the production tubing andbeing communicably coupled to the crossover coupling, and a surveillanceline extending from the crossover coupling external to the outercompletion string and interposing the at least one formation zone andthe at least one sand screen, the surveillance line being communicablycoupled to the interval control valve.

In other embodiments, a method of producing from one or more formationzones is disclosed. The method may include arranging an outer completionstring within a wellbore adjacent the one or more formation zones, theouter completion string having at least one sand screen arrangedthereabout and an interval control valve coupled to the at least onesand screen, communicably coupling a production tubing to the completionstring at a crossover coupling having one or more control linesextending thereto, communicably coupling a surveillance line to the oneor more control lines at the crossover coupling, the surveillance lineextending from the crossover coupling external to the outer completionstring and interposing the one or more formation zones and the at leastone sand screen, and actuating the at least one interval control valveto initiate production into the outer completion string, the at leastone interval control valve being communicably coupled to thesurveillance line.

In yet other embodiments, a method of deploying a single trip multi-zonecompletion system is disclosed. The method may include locating an innerservice tool within an outer completion string arranged within awellbore that penetrates one or more formation zones, the outercompletion string having at least one sand screen arranged thereaboutand an interval control valve coupled to the at least one sand screen,treating the one or more formation zones with the inner service tool,wherein a surveillance line extends external to the outer completionstring and interposes the one or more formation zones and the at leastone sand screen, retrieving the inner service tool from within the outercompletion string, communicably coupling a production tubing to thecompletion string at a crossover coupling having one or more controllines extending thereto, communicably coupling the surveillance line tothe one or more control lines at the crossover coupling, and actuatingthe at least one interval control valve to initiate production into theouter completion string, the at least one interval control valve beingcommunicably coupled to the surveillance line.

The features and advantages of the present invention will be readilyapparent to those skilled in the art upon a reading of the descriptionof the preferred embodiments that follows.

BRIEF DESCRIPTION OF THE DRAWINGS

The following figures are included to illustrate certain aspects of thepresent invention, and should not be viewed as exclusive embodiments.The subject matter disclosed is capable of considerable modifications,alterations, combinations, and equivalents in form and function, as willoccur to those skilled in the art and having the benefit of thisdisclosure.

FIG. 1 is an exemplary single trip multi-zone completion system,according to one or more embodiments.

FIG. 2 illustrates a partial cross-sectional view of the single tripmulti-zone completion system of FIG. 1 with an exemplary productiontubing associated therewith, according to one or more embodiments.

DETAILED DESCRIPTION

The present invention relates to the treatment of subterraneanproduction intervals and, more particularly, to gravel packing,fracturing, and production of multiple production intervals with asingle trip multi-zone completion system.

The exemplary single trip multi-zone systems and methods disclosedherein allow multiple zones of a wellbore to be gravel packed andfractured in the same run-in trip into the wellbore. An exemplaryproduction tubing may be extended into an outer completion stringconfigured to regulate and monitor production from each productioninterval. A control line extends along the sand face pack and allowsoperators to monitor production operations, including measuring fluidand well environment parameters at each point within the system. Thecontrol line also allows the operator to manipulate one or more flowcontrol devices, thereby serving to regulate the production flow ratethrough associated sand screens. As a result, hydrocarbons present ineach production interval may be intelligently produced. The flow controldevices may be arranged within a corresponding sand screen, andtherefore not restrict the inner diameter of the completion string. Thismaximizes the flow rate potential within the completion string ascoupled to the production tubing that extends from the surface.

Referring to FIG. 1, illustrated is an exemplary single trip multi-zonecompletion system 100, according to one or more embodiments. Asillustrated, the system 100 may include an outer completion string 102that may be coupled to a work string 104 that is extended longitudinallywithin a wellbore 106. The wellbore 106 may penetrate multiple formationzones 108 a, 108 b, and 108 c, and the outer completion string 102 maybe extended into the wellbore 106 until being arranged or otherwisedisposed generally adjacent the formation zones 108 a-c. The formationzones 108 a-c may be portions of a common subterranean formation orhydrocarbon-bearing reservoir. Alternatively, one or more of theformation zones 108 a-c may be portion(s) of separate subterraneanformations or hydrocarbon-bearing reservoirs. Although only threeformation zones 108 a-c are depicted in FIG. 1, it will be appreciatedthat any number of formation zones 108 a-c (including one) may betreated or otherwise serviced using the system 100, without departingfrom the scope of the disclosure. Moreover, the term “zone” as usedherein, is not limited to one type of rock formation or type, but mayinclude several types, without departing from the scope of thedisclosure.

As is depicted in FIG. 1, the wellbore 106 may be lined with a string ofcasing 110 and properly cemented therein, as known in the art. In atleast one embodiment, a cement plug 112 may be formed at the bottom ofthe casing 110. In other embodiments, however, the system 100 may bedeployed or otherwise operated in an open-hole section of the wellbore106, without departing from the scope of the disclosure. As will bediscussed in greater detail below, the completion string 102 may bedeployed or otherwise set within the wellbore 106 in a single trip andused to hydraulically fracture (“frack”) and gravel pack the variousproduction intervals or formation zones 108 a-c, and subsequentlyintelligently regulate hydrocarbon production from each productioninterval.

Prior to deploying the system 100 in the wellbore 106, however, a sumppacker 114 may be lowered into the wellbore 106 and set by wire line ata predetermined location below the various formation zones 108 a-c. Oneor more perforations 116 may be then be formed in the casing 110 at eachformation zone 108 a-c. The perforations 116 may provide fluidcommunication between each respective formation zone 108 a-c and theannulus formed between the outer completion string 102 and the casing110. Particularly, a first annulus 118 a may be generally definedbetween the first formation zone 108 c and the outer completion string102. Second and third annuli 118 b and 118 c may similarly be definedbetween the second and third formation zones 108 b and 108 c,respectively, and the outer completion string 102.

The outer completion string 102 may have a top packer 120 includingslips (not shown) configured to support the outer completion string 102within the casing 110 when properly deployed adjacent the productionintervals. In some embodiments, the top packer 120 may be aVERSA-TRIEVE® hangar packer commercially available from HalliburtonEnergy Services of Houston, Tex., USA. Disposed below the top packer 120may be one or more isolation packers 122 (two shown), one or morecirculating sleeves 124 (three shown in dashed), and one or more sandscreens 126 (three shown).

Specifically, arranged below the top packer 120 may be a firstcirculating sleeve 124 a (shown in dashed) and a first sand screen 126a. A first isolation packer 122 a may be disposed below the first sandscreen 126 a, and a second circulating sleeve 124 b (shown in dashed)and a second sand screen 126 b may be disposed below the first isolationpacker 122 a. A second isolation packer 122 b may be disposed below thesecond sand screen 126 b, and a third circulating sleeve 124 c (shown indashed) and a third sand screen 126 c may be disposed below the secondisolation packer 122 b. Those skilled in the art will readily recognizethat more isolation packers 122, circulating sleeves 124, and sandscreens 126 may be employed, without departing from the disclosure, anddepending on the length and number of production intervals desired.

Each circulating sleeve 124 a-c may be movably arranged within thecompletion string 102 and configured to axially translate between openand closed positions. Although described herein as movable sleeves,those skilled in the art will readily recognize that each circulatingsleeve 124 a-c may be any type of flow control device, without departingfrom the scope of the disclosure. First, second, and third ports 128 a,128 b, and 128 c may be defined in the outer completion string 102 atthe first, second, and third circulating sleeves 124 a-c, respectively.When the circulating sleeves 124 a-c are moved into their respectiveopen positions, the ports 128 a-c are opened or otherwise incrementallyexposed and may thereafter provide fluid communication between theinterior of the completion string 102 and the corresponding annuli 118a-c.

Each sand screen 126 a-c may include a corresponding flow control device130 a, 130 b, and 130 c (shown in dashed) movably arranged therein andalso configured to axially translate between open and closed positions.In some embodiments, each flow control device 130 a-c may becharacterized as a sleeve, such as a sliding sleeve that is axiallytranslatable within its associated sand screen 126 a-c. As will bediscussed in greater detail below, each flow control device 130 a-c maybe moved or otherwise manipulated in order to facilitate fluidcommunication between the formation zones 108 a-c and the outercompletion string 102 via the corresponding sand screens 126 a-c. As aresult, the flow control devices 130 a-c may be characterized as orotherwise form part of an associated interval control valve.

In order to deploy the outer completion string 102 within the wellbore106, it may first be assembled at the surface starting from the bottomup until it is completely assembled and suspended in the wellbore 106 upto a packer or slips arranged at the surface. The completion string 102may then be lowered into the wellbore 102 on the work string 104, whichis generally made up to the top packer 120. In some embodiments, theouter completion string 102 is lowered into the wellbore 106 untilengaging the sump packer 114. In other embodiments, the outer completionstring 102 may be lowered into the wellbore 106 and stung into the sumppacker 114. In yet other embodiments, the sump packer 114 is omittedfrom the system 100 and the completion string 102 may instead be blankedoff at its bottom end so that there is no inadvertent productiondirectly into the outer completion string 102 without first passingthrough at least the third sand screen 126 c.

Upon aligning the sand screens 126 a-c with the corresponding productionzones 108 a-c, the top packer 120 may be set and serves to suspend theouter completion string 102 within the wellbore 106. The isolationpackers 122 a,b may also be set at this time, thereby axially definingeach annulus 118 a-c and further defining the individual productionintervals corresponding to the various formation zones 108 a-c.

At this point, an inner service tool (not shown), also known as a gravelpack service tool, may be assembled and lowered into the outercompletion string 102 on a work string (not shown) made up of drill pipeor tubing. The inner service tool is positioned in the first zone to betreated, e.g., the third production interval or formation zone 108 c.The inner service tool may include one or more shifting tools (notshown) used to open and/or close the circulating sleeves 124 a-c and theflow control devices 130 a-c. In some embodiments, for example, theinner service tool has two shifting tools arranged thereon or otherwiseassociated therewith; one shifting tool configured to open thecirculating sleeves 124 a-c and the flow control devices 130 a-c, and asecond shifting tool configured to close the circulating sleeves 124 a-cand flow control devices 130 a-c. In other embodiments, more or lessthan two shifting tools may be used, without departing from the scope ofthe disclosure. In yet other embodiments, the shifting tools may beomitted entirely from the inner service tool and instead the circulatingsleeves 124 a-c and flow control devices 130 a-c may be remotelyactuated, such as by using actuators, solenoids, pistons, and the like.

Before producing hydrocarbons from the various formation zones 108 a-cpenetrated by the outer completion string 102, each formation zone 108a-c may be hydraulically fractured in order to enhance hydrocarbonproduction, and each annulus 118 a-c may also be gravel packed to ensurelimited sand production into the completion string 102 duringproduction. The fracturing and gravel packing processes for the outercompletion string 102 may be accomplished sequentially or otherwise instep-wise fashion for each individual formation zone 108 a-c, startingfrom the bottom of the completion string 102 and proceeding in an upholedirection (i.e., toward the surface of the well).

In one embodiment, for example, the third production interval orformation zone 108 c may be fractured and the third annulus 118 c may begravel packed prior to proceeding sequentially to the second and firstformation zones 108 b and 108 a. The third annulus 118 c may be definedgenerally in the axial direction between the sump packer 114 and thesecond isolation packer 122 b. The one or more shifting tools associatedwith the inner service tool may be used to open the third circulatingsleeve 124 c and the third flow control device 130 c disposed within thethird sand screen 126 c. In other embodiments, the third circulatingsleeve 124 c and/or flow control device 130 c may be remotely actuated(i.e., hydraulically, electromechanically, etc.) using actuators,solenoids, pistons, or the like, without departing from the scope of thedisclosure.

A fracturing fluid may then be pumped down the work string and into theinner service tool. In some embodiments, the fracturing fluid mayinclude a base fluid, a viscosifying agent, proppant particulates(including a gravel slurry), and one or more additives, as generallyknown in the art. The incoming fracturing fluid may be directed out ofthe outer completion string 102 and into the third annulus 118 c via thethird port 128 c. Continued pumping of the fracturing fluid forces thefracturing fluid into the third formation zone 108 c through theperforations 116 in the casing string 110, thereby creating, enhancingand extending a fracture network therein while the accompanying proppantserves to support the fracture network in an open configuration. Theincoming gravel slurry builds in the annulus 118 c between the sumppacker 114 and the second isolation packer 122 b and begins to form whatis referred to as a “sand face” pack. The sand face pack, in conjunctionwith the third sand screen 126 c, serves to prevent the influx of sandor other particulates from the third formation zone 108 c into the outercompletion string 102 during production operations.

Once a desired net pressure is built up in the third formation zone 108c, the fracturing fluid injection rate is stopped. The inner servicetool is then axially moved to position in the reverse position and areturn flow of fracturing fluid flows through the work string 104 inorder to reverse out any excess proppant that may remain in the workstring 104. When the proppant is successfully reversed, the thirdcirculating sleeve 124 c and the third flow control device 130 c areclosed using, for example, the one or more shifting tools, and the thirdannulus 118 c is then pressure tested to verify that the correspondingcirculating sleeve 124 c and flow control device 130 c are properlyclosed. At this point, the third formation zone 108 c has beensuccessfully fractured and the third annulus 118 c has been gravelpacked.

The inner service tool (i.e., the gravel pack service tool) may then beaxially moved within the outer completion string 102 to locate thesecond formation zone 108 b and the first formation zone 108 a,successively, where the foregoing process is repeated in order tofracture the first and second formation zones 108 a,b and gravel packthe first and second annuli 118 a,b. The second annulus 118 b may begenerally defined in the axial direction between the first and secondisolation packers 122 a,b. Upon locating the second production intervalor formation zone 108 b, the one or more shifting tools (or remotelyactuated actuators, pistons, solenoids, etc.) may be used to open thesecond circulating sleeve 124 b and flow control device 130 b.Fracturing fluid may then be pumped into the inner service tool anddirected into the second annulus 118 b via the second port 128 b. Theinjected fracturing fluid generates and extends a fracture network intothe second formation zone 108 b via the perforations 116 in the casingstring 110, and the gravel slurry adds to the sand face pack in thesecond annulus 118 b between the first and second isolation packers 122a,b.

Once the second annulus 118 b is pressure tested, the inner service tool(i.e., the gravel pack service tool) may then be axially moved to locatethe first formation zone 108 a and again repeat the foregoing process.The first annulus 118 a may be generally defined in the axial directionbetween the top packer 120 and the first isolation packer 122 a. Uponlocating the first production interval or formation zone 108 a, the oneor more shifting tools (or remotely actuated actuators, pistons,solenoids, etc.) may be used to open the first circulating sleeve 124 aand flow control device 130 a, and fracturing fluid is subsequentlypumped into the inner service tool and directed into the first annulus118 a via the first port 128 a. The injected fracturing fluid generatesand extends a fracture network into the first formation zone 108 a viathe perforations 116 in the casing string 110, and the gravel slurryadds gravel pack to the sand face pack in the first annulus 118 a. Oncethe first annulus 118 a is pressure tested, the inner service tool maybe removed from the outer completion string 102 and the well altogether,with the circulation sleeves 124 a-c and flow control devices 130 a-cbeing closed and providing isolation during installation of theremainder of the completion, as discussed below. At this time, the workstring 104 may be detached from the completion string 102 at the toppacker 120 and also retrieved to the surface.

Still referring to FIG. 1, the system 100 may further include asurveillance line 132 extending externally along the outer completionstring 102 and within the gravel pack of each annulus 118 a-c in eachformation zone 108 a-c. As will be described in greater detail below,the surveillance line 132 may include one or more control lines thatextend from a crossover coupling (not shown in FIG. 1) arranged withinthe completion string 102. The isolation packers 122 a,b may include orotherwise be configured for control line bypass which allows thesurveillance line 132 to pass therethrough external to the outercompletion string 102.

The surveillance line 132 may be representative of or otherwise includeone or more electrical, hydraulic, and/or fiber optic control linescommunicably coupled to various sensors, gauges, and/or devices arrangedalong the sand face pack and within each gravel packed annulus 118 a-c.The surveillance line 132 may include, for example, a fiber optic lineand one or more accompanying fiber optic gauges or sensors (not shown).The fiber optic line may be deployed along the sand face pack and theassociated gauges/sensors may be configured to measure and reportvarious fluid properties and well environment parameters within eachgravel packed annulus 118 a-c. For instance, the fiber optic line may beconfigured to measure pressure, temperature, fluid density, vibration,seismic waves (e.g., flow-induced vibrations), water cut, flow rate,combinations thereof, and the like within the sand face pack. In someembodiments, the fiber optic line may be configured to measuretemperature along the entire axial length of each sand screen 126 a-c,such as through the use of various fiber optic distributed temperaturesensors or single point sensors arranged along the sand face pack, andotherwise measure fluid pressure in discrete or predetermined locationswithin the sand face pack.

The surveillance line 132 may further include an electrical line coupledto one or more electric pressure and temperature gauges/sensors situatedalong the outside of the completion string 102. Such gauges/sensors maybe arranged adjacent to each sand screen 126 a-c, for example, indiscrete locations on one or more gauge mandrels (not shown). Inoperation, the electrical line may be configured to measure fluidproperties and well environment parameters within each gravel packedannulus 118 a-c. Such fluid properties and well environment parametersinclude, but are not limited to, pressure, temperature, fluid density,vibration, seismic waves (e.g., flow-induced vibrations), radioactivity,water cut, flow rate, combinations thereof, and the like. In someembodiments, the electronic gauges/sensors can be ported to the innerdiameter of each sand screen 126 a-c.

Accordingly, the fiber optic and electrical lines of the surveillanceline 132 may provide an operator with two sets of monitoring data forthe same or similar location within the sand face pack or productionintervals. In operation, the electric and fiber optical gauges may beredundant until one technology fails or otherwise malfunctions. As willbe appreciated by those skilled in the art, using both types ofinstrumenting methods provides a more robust monitoring system againstfailures. Moreover, this redundancy may aid in accurately diagnosingformation problems or issues with the wellbore equipment, such as theflow control devices 130 a-c.

The surveillance line 132 may further include one or more hydrauliclines. In some embodiments, one hydraulic line may be configured toprovide a conduit for deploying additional fiber optic fibers oradditional electrical lines into the sand face pack. In otherembodiments, a hydraulic line may be configured to convey hydraulicpressure to one or more one or more mechanical actuators (not shown)arranged adjacent or otherwise within each sand screen 126 a-c andcommunicably coupled to the flow control devices 130 a-c. Suchmechanical actuators may include any hydraulically-actuated actuators,pistons, solenoids, etc. known to those skilled in the art. In exemplaryoperation, the hydraulic line may be configured to power the mechanicalactuator in order to facilitate the incremental movement of the flowcontrol devices 130 a-c between the open and closed positions, therebychoking or otherwise regulating the fluid flow through the associatedsand screens 126 a-c.

In one or more embodiments, an electrical line may replace the hydraulicline used to power the flow control devices 130 a-c. Specifically, anelectrical line may provide electrical power to one or moreelectromechanical devices or motors communicably coupled to the flowcontrol devices 130 a-c. Actuation of such electromechanical devices mayequally facilitate the incremental movement of the flow control devices130 a-c between the open and closed positions, thereby choking orotherwise regulating the fluid flow through the associated sand screens126 a-c.

Referring now to FIG. 2, with continued reference to FIG. 1, illustratedis a partial cross-sectional view of the single trip multi-zonecompletion system 100 with an exemplary production tubing 202 extendedto or otherwise arranged at least partially within the outer completionstring 102, according to one or more embodiments. As illustrated, theouter completion string 102 may include a fluid loss valve 204 arrangedtherein above the first formation zone 108 a and generally below the toppacker 120. In operation, the fluid loss valve 204 may be configured toopen and close in order to isolate the formation zones 108 a-c from thesurface and thereby prevent fluid loss from the production intervalsprior to production operations being commenced. In at least oneembodiment, the fluid loss valve 204 may be closed as the inner servicetool (discussed above with reference to FIG. 1) is retrieved to thesurface. In some embodiments, the fluid loss valve 204 may be an FS2fluid loss isolation barrier valve commercially available throughHalliburton Energy Services of Houston, Tex., USA. In other embodiments,the fluid loss valve 204 may be any other suitable check or isolationvalve known to those skilled in the art, and may be remotely actuatedvia either wired or wireless communication.

The production tubing 202 may include a safety valve 206 arranged in orotherwise forming part of the production tubing 202. In someembodiments, the safety valve 206 may be a surface-controlled subsurfacesafety valve, or the like. In other embodiments, the safety valve 206may be a tubing-retrievable safety valve, such as the DEPTHSTAR® safetyvalve commercially-available from Halliburton Energy Services ofHouston, Tex., USA. The safety valve 206 may be controlled using a firstcontrol line 208 that extends to the safety valve 206 from a remotelocation, such as the Earth's surface or another location within thewellbore 106. In at least one embodiment, the control line 208 may be asurface-controlled subsurface safety valve control line configured tocontrol the actuation or operation of the safety valve 206.

The production tubing 202 may also include a travel joint 210 arrangedin or otherwise forming part of the production tubing 202. In operation,the travel joint 210 may be configured to expand and/or contractaxially, thereby effectively lengthening and/or contracting the axiallength of the production tubing 202 such that a well head tubing hangermay be accurately attached at the top of the production tubing stringand landed inside of the wellhead. The travel joint 210 may be actuatedor powered either electrically, hydraulically, or with tubingcompression, as known in the art.

The production tubing 202 may be run into the wellbore 106 and at leastpartially extended into the completion string 102. As illustrated, theproduction tubing 202 may be stung into or otherwise communicablycoupled to the completion string 102 at a crossover coupling 212. Insome embodiments, the crossover coupling 212 may be an electro-hydraulicwet connect that provides an electrical wet mate connection betweenopposing male and female connectors. In other embodiments, the crossovercoupling 212 may be an inductive coupler providing an electromagneticcoupling or connection with no contact between the crossover coupling212 and the internal tubing. Exemplary crossover couplings 212 that maybe used in the disclosed system 100 are described in U.S. Pat. Nos.8,082,998 and 8,079,419, 4,806,928 and in U.S. patent application Ser.No. 13/405,269, each of which is hereby incorporated by reference intheir entirety.

A second control line 214 may extend to the crossover coupling 212external to the production tubing 202 from a remote location (e.g., thesurface of the well or another location within the wellbore 106).Although only one control line 214 is shown in FIG. 2, it will beappreciated that any number of control lines 214 may be used in thesystem 100, without departing from the scope of the disclosure. In someembodiments, for example, the second control line 214 may be a flatpackcontrol umbilical, or the like, and may be representative of orotherwise include one or more hydraulic lines, one or more electricallines, and/or one or more fiber optic lines. The hydraulic andelectrical lines may be configured to provide hydraulic and electricalpower to various downhole equipment. In some embodiments, the electricallines may also be configured to receive and convey command signals andotherwise transmit data to and from the surface of the well. The fiberoptic and/or electrical lines may be communicably coupled to varioussensors and/or gauges arranged along the production tubing 202 andcompletion string 102 and otherwise configured to transmit one or morefluid and/or well environment parameters and data to the surface of thewell.

At the crossover coupling 212 the second control line 214 may becommunicably coupled to the surveillance line 132, which may penetrateand exit the completion string 102 therebelow and thereafter extendexternal to the completion string 102 within the gravel packed annuli118 a-c, as generally described and discussed above. Accordingly, uponproperly coupling the production tubing 202 to the completion string 102at the crossover coupling 212, the crossover coupling 212 may beconfigured to provide either an electro-hydraulic wet mate connectionand/or an electromagnetic connection between the surveillance line 132and the second control line 214. As a result, the second control line214 may be communicably coupled to the surveillance line 132 such thatthe second control line 214 is, in effect, extended into the sand facepack of each gravel packed annulus 118 a-c in the form of thesurveillance line 132.

The surveillance line 132 may thus be provided with the hydraulic,electrical, and fiber optic control lines, as generally described above.Accordingly, the surveillance line 132 may facilitate real timemonitoring and reporting of fluid and/or well environment parameters,such as pressure, temperature, seismic waves (e.g., flow-inducedvibrations), radioactivity, compaction, water cut, flow rate, etc., andmay also provide the hydraulic and/or electrical power needed to actuatethe various flow control devices 130 a-c. As illustrated, the secondcontrol line 214 may also extend to the travel joint 210 and providehydraulic and/or electrical power thereto. As a result, the travel joint210 may be able to axially expand and contract and its position ordegree of expansion/contraction may be measured and reported to thesurface in real time.

Once the production tubing 202 is appropriately situated within thecompletion string 102, and otherwise communicably coupled thereto at thecrossover coupling 212, an upper packer 216 may be set within the casingstring 110, thereby anchoring the production tubing 202 within thewellbore 106. In some embodiments, the upper packer 116 may be aretrievable packer, such as an HF-1 packer commercially available fromHalliburton Energy Services of Houston, Tex., USA. Similar to theisolation packers 122 a,b, the upper packer 216 may also include orotherwise be configured for control line bypass which allows the secondcontrol line 214 to pass therethrough external to the production tubing202.

In exemplary operation, production of fluids from each productioninterval or formation zone 108 a-c may be commenced by first opening thefluid loss valve 204. In some embodiments, this may be done by applyinghydraulic pressure through the production tubing 202. In otherembodiments, the fluid loss valve 204 may be opened by actuating one ormore downhole actuators, pistons, solenoids, motors, etc. (not shown),without departing from the scope of the disclosure. Once the fluid lossvalve 204 is open, the flow control devices 130 a-c in each individualsand screen 126 a-c may be intelligently controlled using the hydraulicand/or electric power provided by the surveillance line 132 to theinterval control valves 218 a-c.

In some embodiments, for example, the flow control devices 130 a-c mayincorporated into or otherwise form an integral part of an associatedinterval control valve 218 a, 218 b, and 218 c, each interval controlvalve 218 a-c being integrated into its corresponding sand screen 126a-c and communicably coupled to the surveillance line 132. Each intervalcontrol valve 218 a-c may be configured to incrementally manipulate theaxial position of each flow control device 130 a-c. For instance, in atleast one embodiment, the interval control valves 218 a-c may include anactuator, solenoid, piston, or similar actuating device (not shown)coupled to its associated flow control device 130 a-c and configured tomove the flow control device 130 a-c. One or more position sensors (notshown) may also be included in or otherwise associated with eachinterval control valve 218 a-c and configured to measure and report theaxial position of each flow control device 130 a-c as moved within withthe associated sand screens 126 a-c.

Accordingly, the position of each flow control device 130 a-c may beknown and adjusted in real-time in order to choke or otherwise regulatethe production flow rate through each corresponding sand screen 126 a-c.In some embodiments, for example, it may be desired to open one or moreof the flow control devices 130 a-c only partially (e.g., 20%, 40%, 60%,etc.) in order to choke production flow from one or more associatedformation zones 108 a-c. In other embodiments, it may be desired to slowor entirely shut down production from a particular production intervalor formation zone 108 a-c and instead produce increased amounts from theremaining production intervals or formation zones 108 a-c.

Each interval control valve 218 a-c may further include one or moresensors or gauges (not shown) configured to measure and report real-timepressure, temperature, and flow rate data for each associated formationzone 108 a-c. The data feedback and accurate flow control capability ofeach flow control device 130 a-c as controlled by the associatedinterval control valves 218 a-c allows an operator to optimize reservoirperformance and enhance reservoir management.

In one or more embodiments, one or more of the interval control valves218 a-c may be a SCRAMS® (Surface Controlled Reservoir Analysis andManagement System) device commercially available through HalliburtonEnergy Services of Houston, Tex., USA. At least one advantage of usingthe SCRAMS® technology is the incorporation of redundant electrical andhydraulic control lines that ensure uninterrupted control of the flowcontrol device 130 a-c even in the event the main electrical and/orhydraulic control lines feeding the particular interval control valve218 a-c are severed or otherwise rendered inoperable. Those skilled inthe art will readily recognize, however, that the interval controlvalves 218 a-c may be any other known downhole tool configured toregulate fluid flow through a flow control device 130 a-c or similardownhole device. Accordingly, the flow control devices 130 a-c may beactuated mechanically, hydraulically, electromechanically,electro-hydraulically, combinations thereof, and the like.

As each flow control device 130 a-c is moved from its closed positioninto an open position (either fully or partially open), a correspondingflow port 220 a, 220 b, and 220 c defined in the outer completion string102 is uncovered or otherwise exposed, thereby allowing the influx offluids into the outer completion string 102 from the respectiveformation zone 108 a-c. In some embodiments, one or more of the flowports 220 a-c may have an elongated or progressively enlarged shape inthe axial direction required to move the flow control device 130 a-cfrom closed to open positions. As the flow control device 130 a-ctranslates to its open position, the volumetric flow rate through thecorresponding flow port 220 a-c may progressively increase proportionalto its progressively enlarged shape. In some embodiments, for example,one or more of the flow ports 220 a-c may exhibit an elongatedtriangular shape which progressively increases volumetric flow potentialin the axial direction, thereby allowing an increased amount of fluidflow as the corresponding flow control device 130 a-c moves to its openposition. In other embodiments, however, one or more of the flow ports220 a-c may exhibit a tear drop shape or the like, and achievesubstantially the same fluid flow increase as the flow control device130 a-c moves axially. Accordingly, each flow control device 130 a-c maybe characterized as an integrated flow control choke device.

In other embodiments, however, one or more of the flow control devices130 a-c may be an autonomous variable flow restrictor. For instance, atleast one of the flow control devices 130 a-c may include a springactuated movable sleeve that opens and closes autonomously, anddepending at least in part on the pressure experienced within eachproduction interval. Such an autonomous inflow control device may proveadvantageous in equalizing fluid flow across multiple productionintervals.

Those skilled in the art will readily appreciate the advantages thedisclosed system 100 may provide. For instance, the interval controldevices 218 a-c and associated flow control devices 130 a-c areintegrated directly into the sand screens 126 a-c, thereby allowing fora larger flow area in the interior of the completion string 102 ascoupled to the production tubing 202. In some embodiments, slim versionsof the flow control devices 130 a-c may be employed, without departingfrom the scope of the disclosure, thereby providing for an even largerflow area in the interior of the completion string 102. As a result, theinner diameter of the completion string 102 is not restricted and flowrate is maximized. Moreover, this allows for larger tools to bypass thecompletion string 102, if needed, in order to extend the depth of thewellbore 106.

Another significant advantage obtained by the system 100 is theinstrumentation of the sand face pack via the surveillance line 132. Themeasurements derived from the surveillance line and its correspondingsensors/gauges may prove highly advantageous in intelligently producingthe hydrocarbons from each formation zone 108 a-c. For instance, byknowing real time production rates and other environmental parametersassociated with each formation zone 108 a-c, an operator may be able toadjust fluid flow rates through each sand screen 126 a-c byincrementally adjusting the flow control devices 130 a-c. As a result,the formation zones 108 a-c may be more efficiently produced, in orderto maximize production and save time and costs. Moreover, by continuallymonitoring the environmental parameters of each formation zone 108 a-c,the operator may be able to determine when a problem has resulted, suchas formation collapse, water break through, or zonal depletion, therebybeing able to proactively manage production.

Various alternative configurations to the single trip multi-zonecompletion system 100 are contemplated herein, without departing fromthe scope of the disclosure. For instance, in some embodiments, the flowcontrol devices 130 a-ca-c may be replaced with inflow control devices,inflow control devices that can be shut off, or adjustable inflowcontrol devices. This may prove advantageous in applications were aninjection well is desired. Such inflow control devices are known tothose skilled in the art, and therefore are not described herein.

Therefore, the present invention is well adapted to attain the ends andadvantages mentioned as well as those that are inherent therein. Theparticular embodiments disclosed above are illustrative only, as thepresent invention may be modified and practiced in different butequivalent manners apparent to those skilled in the art having thebenefit of the teachings herein. Furthermore, no limitations areintended to the details of construction or design herein shown, otherthan as described in the claims below. It is therefore evident that theparticular illustrative embodiments disclosed above may be altered,combined, or modified and all such variations are considered within thescope and spirit of the present invention. The invention illustrativelydisclosed herein suitably may be practiced in the absence of any elementthat is not specifically disclosed herein and/or any optional elementdisclosed herein. While compositions and methods are described in termsof “comprising,” “containing,” or “including” various components orsteps, the compositions and methods can also “consist essentially of” or“consist of” the various components and steps. All numbers and rangesdisclosed above may vary by some amount. Whenever a numerical range witha lower limit and an upper limit is disclosed, any number and anyincluded range falling within the range is specifically disclosed. Inparticular, every range of values (of the form, “from about a to aboutb,” or, equivalently, “from approximately a to b,” or, equivalently,“from approximately a-b”) disclosed herein is to be understood to setforth every number and range encompassed within the broader range ofvalues. Also, the terms in the claims have their plain, ordinary meaningunless otherwise explicitly and clearly defined by the patentee.Moreover, the indefinite articles “a” or “an,” as used in the claims,are defined herein to mean one or more than one of the element that itintroduces. If there is any conflict in the usages of a word or term inthis specification and one or more patent or other documents that may beincorporated herein by reference, the definitions that are consistentwith this specification should be adopted.

1. A single trip multi-zone completion system, comprising: an outercompletion string having at least one sand screen arranged thereaboutand an interval control valve coupled to the at least one sand screen; aproduction tubing communicably coupled to the outer completion string ata crossover coupling; a control line extending external to theproduction tubing and being communicably coupled to the crossovercoupling; and a surveillance line extending from the crossover couplingexternal to the outer completion string and interposing the at least oneformation zone and the at least one sand screen, the surveillance linebeing communicably coupled to the interval control valve.
 2. The systemof claim 1, further comprising a fluid loss valve arranged within theouter completion string.
 3. The system of claim 1, wherein the crossovercoupling is at least one of an electro-hydraulic wet connect providingan electrical wet mate connection and an inductive coupler providing anelectromagnetic connection.
 4. (canceled)
 5. The system of claim 1,wherein the control line comprises one or more hydraulic lines, one ormore electrical lines, and/or one or more fiber optic lines.
 6. Thesystem of claim 1, wherein the surveillance line comprises one or morehydraulic lines, one or more electrical lines, and/or one or more fiberoptic lines.
 7. The system of claim 1, wherein the surveillance lineincludes one or more associated gauges and/or sensors configured tomeasure and report fluid and well parameters external to the outercompletion string.
 8. The system of claim 7, wherein the fluid and wellenvironment parameters comprise at least one of pressure, temperature,fluid density, seismic activity, vibration, compaction, and anycombination thereof.
 9. (canceled)
 10. The system of claim 1, furthercomprising a flow control device arranged within the at least oneinterval control valve and movable between an open position and a closedposition.
 11. The system of claim 10, wherein the flow control device isa sleeve, and when in the open position one or more flow ports definedin the outer completion string are exposed and allow fluid flow into theinterior of the production tubing.
 12. (canceled)
 13. (canceled)
 14. Amethod of producing from one or more formation zones, comprising:arranging an outer completion string within a wellbore adjacent the oneor more formation zones, the outer completion string having at least onesand screen arranged thereabout and an interval control valve coupled tothe at least one sand screen; communicably coupling a production tubingto the completion string at a crossover coupling having one or morecontrol lines extending thereto; communicably coupling a surveillanceline to the one or more control lines at the crossover coupling, thesurveillance line extending from the crossover coupling external to theouter completion string and interposing the one or more formation zonesand the at least one sand screen; and actuating the at least oneinterval control valve to initiate production into the outer completionstring, the at least one interval control valve being communicablycoupled to the surveillance line.
 15. (canceled)
 16. The method of claim14, further comprising measuring one or more fluid and wellenvironmental parameters external to the outer completion string withone or more gauges and/or sensors associated with the surveillance line.17. (canceled)
 18. The method of claim 14, wherein actuating the atleast one interval control valve further comprises regulating a fluidflow through the sand screen and into the outer completion string withthe at least one interval control valve.
 19. The method of claim 18,further comprising choking the fluid flow into the outer completionstring with the at least one interval control valve.
 20. The method ofclaim 14, wherein actuating the at least one interval control valvefurther comprises moving a flow control device arranged within the atleast one sand screen between a closed position and an open position.21. The method of claim 20, further comprising choking a fluid flow intothe outer completion string by incrementally moving the flow controldevice partially between the closed and open positions with the at leastone interval control valve.
 22. A method of deploying a single tripmulti-zone completion system, comprising: locating an inner service toolwithin an outer completion string arranged within a wellbore thatpenetrates one or more formation zones, the outer completion stringhaving at least one sand screen arranged thereabout and an intervalcontrol valve coupled to the at least one sand screen; treating the oneor more formation zones with the inner service tool, wherein asurveillance line extends external to the outer completion string andinterposes the one or more formation zones and the at least one sandscreen; retrieving the inner service tool from within the outercompletion string; communicably coupling a production tubing to thecompletion string at a crossover coupling having one or more controllines extending thereto; communicably coupling the surveillance line tothe one or more control lines at the crossover coupling; and actuatingthe at least one interval control valve to initiate production into theouter completion string, the at least one interval control valve beingcommunicably coupled to the surveillance line.
 23. The method of claim22, wherein retrieving the inner service tool further comprises closinga fluid loss valve arranged within the outer completion string.
 24. Themethod of claim 23, further comprising opening the fluid loss valve oncethe production tubing is communicably coupled to the completion string.25. (canceled)
 26. (canceled)
 27. The method of claim 22, furthercomprising measuring one or more fluid and well environmental parametersexternal to the outer completion string with one or more gauges and/orsensors associated with the surveillance line.
 28. The method of claim27, further comprising measuring compaction of a gravel pack in the oneor more formation zones with one or more gauges and/or sensors.
 29. Themethod of claim 27, further comprising monitoring the one or moreformation zones for water break through or zonal depletion with the oneor more gauges and/or sensors.
 30. The method of claim 22, whereinactuating the at least one interval control valve further comprisesregulating a fluid flow through the sand screen and into the outercompletion string with the at least one interval control valve.
 31. Themethod of claim 30, further comprising choking the fluid flow into theouter completion string with the at least one interval control valve.32. The method of claim 22, wherein actuating the at least one intervalcontrol valve further comprises moving a flow control device arrangedwithin the at least one sand screen between a closed position and anopen position.
 33. The method of claim 32, further comprising choking afluid flow into the outer completion string by incrementally moving theflow control device partially between the closed and open positions withthe at least one interval control valve.
 34. The method of claim 22,wherein treating the one or more formation zones comprises hydraulicallyfracturing and gravel packing the one or more formation zones.
 35. Themethod of claim 22, further comprising: detaching the production tubingfrom the outer completion string; retrieving the production tubing to awell surface while the outer completion string remains within thewellbore adjacent the one or more formation zones; re-locating theproduction tubing within the outer completion string; and communicablycoupling the production tubing to the outer completion string at thecrossover coupling once again.